This section is intended to introduce various aspects of the art, which may be associated with the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as including admissions of prior art.
Modern society is greatly dependent on the use of hydrocarbons for fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface rock, soil or sand formations that can be termed “reservoirs.” Removing hydrocarbons from such reservoirs depends on numerous physical properties of the formations, such as the permeability of the formations containing the hydrocarbons, the ability of the hydrocarbons to flow through the formations, and the proportion of hydrocarbons present, among other things.
Easily harvested sources of hydrocarbons are dwindling, leaving less accessible sources to satisfy future energy needs. However, as the costs of hydrocarbons increase, these less accessible sources become more economically attractive. For example, the harvesting of oil sands to remove hydrocarbons has become more extensive as it has become more economical. The hydrocarbons harvested from these reservoirs may have relatively high viscosities, for example, ranging from 1000 centipoise to 20 million centipoise with API (American Petroleum Institute) densities ranging from 8 API, or lower, up to 20 API, or higher. Accordingly, the hydrocarbons may include heavy oils, bitumen, or other carbonaceous materials, collectively referred to herein as “heavy oil,” which are difficult to recover using standard techniques.
Several methods have been developed to remove hydrocarbons from oil sands. For example, strip or surface mining may be performed to access the oil sands, which can then be treated with hot water or steam to extract the oil. However, deeper formations may not be accessible using a strip mining approach. For these formations, a well can be drilled into the reservoir and steam, hot air, solvents, or combinations thereof, can be injected to release the hydrocarbons. The released hydrocarbons may then be collected by the injection well or by other wells (i.e. production wells) and brought to the surface.
A number of techniques have been developed for harvesting heavy oil from subsurface reservoirs using well-based recovery techniques. These operations include a suite of steam based in-situ thermal recovery techniques, such as cyclic steam stimulation (CSS), steam flooding and steam assisted gravity drainage (SAGD) as well as surface mining and their associated thermal based surface extraction techniques.
For example, CSS techniques includes a number of enhanced recovery methods for harvesting heavy oil from formations that use steam heat to lower the viscosity of the heavy oil. These steam assisted hydrocarbon recovery methods are described in U.S. Pat. No. 3,292,702 to Boberg, and U.S. Pat. No. 3,739,852 to Woods, et al., among others. CSS and other steam flood techniques have been utilized worldwide, beginning in about 1956 with the utilization of CSS in the Mene Grande field in Venezuela and steam flooding in the early 1960s in the Kem River field in California.
The CSS process may raise the steam injection pressure above the formation fracturing pressure to create fractures within the formation and enhance the surface area access of the steam to the heavy oil, although CSS may also be practiced at pressures that do not fracture the formation. The steam raises the temperature of the heavy oil during a heat soak phase, lowering the viscosity of the heavy oil. The injection well may then be used to produce heavy oil from the formation. The cycle is often repeated until the cost of injecting steam becomes uneconomical, for instance if the cost is higher than the money made from producing the heavy oil. Successive steam injection cycles re-enter earlier created fractures and, thus, the process becomes less efficient over time. CSS is generally practiced in vertical wells, but systems are operational in horizontal wells.
Solvents may be used in combination with steam in CSS processes, such as in mixtures with the steam or in alternate injections between steam injections. These techniques are described in Canadian Patent No. 2,342,955 to Leaute, U.S. Pat. No. 4,280,559 to Best, U.S. Pat. No. 4,519,454 to McMillen, and U.S. Pat. No. 4,697,642 to Vogel, among others.
Steam flooding is a process in which steam is injected from a series of vertical well injectors or horizontal well injectors and heavy oil is heated and pushed towards a series of vertical producer wells or horizontal producer wells. This process can be used as a late life process after a CSS operation. The process in late life is essentially a gravity drainage process. Solvent can be injected with steam to enhance the process. Further details may be obtained, for example, from Zhihong Liu and Shane D. Stark, “Reservoir Stimulation Modelling of the Mature Cold Lake Steaming Operations”, Society of Petroleum Engineers, SPE 160491, presented in Calgary, Alberta, 12-14 Jun. 2012 (the disclosure of which is incorporated herein by reference).
Various embodiments of the SAGD process are described in Canadian Patent No. 1,304,287 to Butler and its corresponding U.S. Pat. No. 4,344,485. In SAGD, two horizontal wells are completed into the reservoir. The two wells are first drilled vertically to different depths within the reservoir. Thereafter, using directional drilling technology, the two wells are extended in the horizontal direction that result in two horizontal wells, vertically spaced from, but otherwise vertically aligned with the other. Ideally, the production well is located above the base of the reservoir but as close as practical to the bottom of the reservoir, and the injection well is located vertically 10 to 30 feet (3 to 10 meters) above the horizontal well used for production.
The upper horizontal well is utilized as an injection well and is supplied with steam from the surface. The steam rises from the injection well, permeating the reservoir to form a vapor chamber that grows over time towards the top of the reservoir, thereby increasing the temperature within the reservoir. The steam, and its condensate, raise the temperature of the reservoir and consequently reduce the viscosity of the heavy oil in the reservoir. The heavy oil and condensed steam will then drain downward through the reservoir under the action of gravity and may flow into the lower production well, whereby these liquids can be pumped to the surface. At the surface of the well, the condensed steam and heavy oil are separated, and the heavy oil may be diluted with appropriate light hydrocarbons for transport by pipeline.
A number of variations of the SAGD process have been developed in an attempt to increase the productivity of the process. For example, U.S. Pat. No. 6,230,814 to Nasr, et al., teaches how the SAGD process can be further enhanced through the addition of small amounts of solvent to the injected steam. Nasr teaches that as the planned SAGD operating pressure declines, the molecular weight of the solvent must be reduced in order to ensure that it is completely vaporized at the planned operating conditions. This approach results in the progressive exclusion of heavier solvents as lower operating pressures (and temperatures) are considered.
Solvents may also be used in concert with steam addition to increase the efficiency of the steam in removing the heavy oils. U.S. Pat. No. 6,230,814 to Nasr, et al., discloses a method for enhancing heavy oil mobility using a steam additive. The method included injecting steam and an additive into the formation. The additive includes a non-aqueous fluid, selected so that the evaporation temperature of the non-aqueous fluid is within about ±150° C. of the steam temperature at the operating pressure. Suitable additives include C1 to C25 hydrocarbons. At least a portion of the additive condenses in the formation. The mobility of the heavy oil obtained with the steam and solvent combination is greater than that obtained using steam alone under substantially similar formation conditions.
Canadian Patent No. 2,323,029 to Nasr and Isaacs discloses a method of producing hydrocarbons involving the injection of steam and an additive. The additive is a non-aqueous fluid having an evaporation temperature within about ±150° C. of the temperature of the steam at the operating pressure of the formation. The additive may be selected from C1 to C25 hydrocarbons.
Canadian Patent No. 2,769,356 to Gupta, Gittins and Bilozir discloses the use of a solvent of a pentane or hexane, or both, as an additive to, or sole component of, a gravity-dominated process for recovering heavy oil from a reservoir. However, the patent teaches that fractions heavier than hexane (such as C7, C8, C9, etc.) are not effective in enhancing the oil recovery process as they precipitate out in the near well vicinity and do not travel to the vapor-liquid interface within the reservoir.
To conserve energy, it has also been suggested to use lower pressure steam for heavy oil production. However, at lower operating pressures, the solubility of the solvents in the heavy oil is reduced, thereby resulting in lower production performance.